1. Field of the Invention
The present invention relates to an additive for drilling fluid shown to be effective as both a sealing agent to reduce seepage loss and a shale stabilizing agent in subterranean wellbores.
2. Prior Art
Drilling fluid or drilling “mud” is utilized during downhole drilling operations. The drilling fluid is pumped down from the surface to the drill tip location and then circulated back to the surface in a continuous operation. The drilling fluid helps lubricate and cool the drill bit during the drilling operation and also carries the drill cuttings to the surface.
Wellbore stability in the drilling of oil and gas wells has been studied for years. Despite numerous studies and many proposed solutions, maintaining a stable wellbore remains a problem. A literature survey showed numerous papers in 2013 alone devoted to this area.
Wellbore stability is particularly a problem when drilling shale. Shale is defined as “a fine-grained, clastic sedimentary rock composed of mud that is a mix of flakes of clay minerals and tiny fragments (silt-sized particles) of other minerals, especially quartz and calcite.” See http://en.wikipedia.org/wiki/Shale and Blatt, Harvey and Robert J. Tracy (1996) “Petrology: Igneous, Sedimentary and Metamorphic”, 2nd ed., Freeman, pp. 281-292. According to Lal, Manohar (1999) “Shale Stability: Drilling Fluid Interaction and Shale Strength”, Society of Petroleum Engineers 54356, 1999 SPE Latin American and Caribbean Petroleum Engineering Conference, Caracas, Venezuela, 21-23 Apr. 1999, “shales make up over 75% of the drilled formations and over 70% of the borehole problems are related to shale instability.” The type and amount of clay in the shale are major causes of wellbore stability problems because clays can interact with the water in the drilling fluid.
Wellbore instability can occur for several reasons, some of which are listed below:
Changes in Mechanical Stress and Rock Strength.                During the drilling process, rock is removed and replaced by drilling fluid. This changes the mechanical forces acting on the remaining rock.        
Differential Pressure Changes.                The column of fluid in the wellbore generates a pressure on the surrounding rock that can be greater or less than the pressure of the fluid inside the rock. The difference in pressure can cause fluid movement either into or out of the rock.        
Osmotic Pressure Differences.                The water in the rock, both internal to the clays and in the pore spaces, will normally have a certain amount of salinity as measured by its water activity. If the drilling fluid has a significantly different salinity, water will tend to move into or out of the rock, depending on whether the drilling fluid is less saline (higher water activity) or more saline (lower water activity) than the formation water.        
Changes in the Clay Structure from Ionic Substitution.                Various hydrated cations (sodium, potassium, calcium, and others) are sandwiched between the silicate layers in clays found in shale, holding the layers together by static charge. Because a potassium cation (K+) is more closely surrounded by its waters of hydration, the clay layers in a K+ containing clay will be more tightly held together. If this type of clay comes in contact with a fluid containing a large amount of sodium ion (Na+), the Na+ will become substituted for the K+, and the clay layers will be less tightly held together. Conversely, if a Na+ containing clay comes in contact with a fluid containing K+, the K+ will substitute for the Na+, and the clay structure will be strengthened. Too much K+ substitution can actually cause the clays to shrink and introduce fractures in the shale. See Horsrud, P. et al., “Interaction Between Shale and Water-Based Drilling Fluids: Laboratory Exposure Tests Give New Insight into Mechanisms and Field Consequences of KCl Contents”, Society of Petroleum Engineers 48986, 1988 SPE Annual Technical Conference and Exhibition, New Orleans, La., 27-30 Sep. 1998.        
Swelling of the Clays.                When the clays in shale absorb water, they tend to swell, increasing the hydraulic pressures in the system.        
Fractures in the Shale.                Fractured shale and weak bedding planes facilitate the movement of fluid into the shale and allow more contact of drilling fluid with the clays.        
Generally speaking, the major way to stabilize shale is to prevent or reduce the interaction of the water in the drilling fluid with the shale. Much of the fluid interaction is time-dependent. That is, the longer the shale is exposed to the drilling fluid, the more likely problems are to develop. Limiting shale exposure to water can be key to preventing wellbore failure.
One successful mechanism for limiting shale exposure to water is to use oil-based or synthetic drilling fluids containing organic low-polar fluids. Oil-based drilling fluids are generally water-in-oil emulsions with the water phase containing a salt such as calcium chloride. In drilling water-wet shales, capillary forces of oil-based muds prevent fluid invasion. See Lal, Manohar, ibid. In addition, the salt concentration in the water phase can be matched to the shale water activity to reduce or eliminate osmotic effects. Drilling fluid density can be adjusted to reduce differential pressures. Ionic substitution is prevented by the presence of the oil surrounding the water droplets of the emulsion. However, oil-based drilling fluids are expensive and may have environmental impacts and disposal problems that limit their use in some cases.
In water-based drilling fluids, because the water comes in direct contact with the shale, a variety of mechanisms have been attempted in order to limit the water interaction with the clays. Potassium chloride (KCl) is frequently used as a component. When used in moderate concentrations, the ionic substitution of K+ for Na+ in the clays can help strengthen the clays and delay hydration. The presence of KCl, sodium chloride (NaCl), or some other salt will also lower the water activity of the fluid, reducing the osmotic tendency of water to migrate into the shales.
Similarly, organic cationic amine compounds have been developed which displace the existing cations in the clay structure and exclude water molecules. See Gomez, Sandra and Patel, Arvind, “Shale Inhibition: What Works?”, Society of Petroleum Engineers 164108, SPE International Symposium on Oilfield Chemistry, The Woodlands, Tex., 8-10 Apr. 2013. Polymeric amine shale inhibitors are longer versions of these amines with multiple cationic sites for binding. Their larger molecular size, however, prevents them from penetrating the clay layers as well as their smaller counterparts. Adsorption is primarily on the surface of the clay.
The use of poly-cationic materials to provide shale stabilization is not new. In the introduction of their paper, Williams and Underdown discuss using multisited cationic materials to more permanently stabilize shales. See Williams, Lewis H. and Underdown, David R., “New Polymer Offers Effective, Permanent Clay Stabilization Treatment”, Society of Petroleum Engineers 8797, Journal of Petroleum Technology, July 1981, pp. 1211-1217. They reference partially hydrolyzed polyacrylamide (PHPA) (Scheuerman, Canadian Patent No. 972,346) Halliburton Services CLA-STA™ and flaxmeal as examples of these materials. See Anderson, D. B. and Edwards, C. D., “Fluid Development for Drilling Sloughing and Heaving Shales”, Petroleum Engineer, September 1977, pp 105-118; Anderson, et al. (U.S. Pat. No. 4,142,595); and Lummus et al. (U.S. Pat. No. 3,723,311).
In their patent, Anderson et al. (U.S. Pat. No. 4,142,595) show the effectiveness of using flaxmeal in a KCl, polymer-viscosified drilling fluid system on maintaining shale integrity of several different shales after rolling 16 hours in the fluid. Several other materials were also tested, but found to be less effective than flaxmeal. In addition to rolling shale samples for 16 hours in the inhibitive fluid, the recovered shale was rolled for an additional 2 hours in fresh water. The flaxmeal/KCl combination was found to continue to protect the shale even after rolling in fresh water.
Plugging of pore holes is also a potential mechanism for reducing fluid migration into the wellbore. However, pores in shales are very small (3-100 nm) (see Lal, Manohar, ibid.) with average pore sizes in the 10 to 30 nm range (see Jung, Chang Min, et al., “High-Performance Water-Based Mud Using Nanoparticles for Shale Reservoirs”, Society of Petroleum Engineers 168799, Unconventional Resources Technology Conference, Denver, Colo., 12-14 Aug. 2013). Among other rules for sizing particles for bridging, Hands et al. proposed that the D90 of the bridging particles should be equal to or less than the pore size of the rock (the size of 90% of the particles should be equal to or less than the pore size). See Hands et al., “Drill-In Fluid Reduces Formation Damage, Increases Production Rates”, Oil and Gas Journal (July 1998). For reference, the particle size of bentonite and barite, commonly used in water-based muds, are in the 0.1 to 100 micron range (100-100,000 nm), much too large for effective filter cake formation or plugging. Jung et al. and others have suggested using nanoparticles in water-based fluids for this purpose. See Ji, L. et al., “Drilling Unconventional Shales with Innovative Water-Based Mud—Part I: Evaluation of Nanoparticles as Physical Shale Inhibitor”, AADE-12-FTCE-50, AADE Fluid Technical Conference, Houston, 12-14 Apr. 2011.
On the other hand, fractures in shales are potentially much larger than the pore holes. Preventing fluid from entering such fractures is also important in delaying clay hydration and time-dependent shale instability. Ground materials such as uintaite (commonly known as Gilsonite) and sized calcium carbonate have been used for this purpose. Anderson et al. recommended the use of treated uintaite as a means of sealing off microfractures in the shale. See Anderson et al., ibid.
Pomerleau (U.S. Patent Publication No. 2010/0230164) addressed lost circulation, seepage loss, and fluid loss control. The patent describes the use of ground pumice, barium, dolomite, anthracite or a combination of these materials in drilling fluids. The patent covers a very broad range of particle sizes (between 100 and 4,000 microns) and an extremely wide range of concentrations (0.01 to 300 ppb). While the patent does advocate anthracite as one possible additive, it does not mention bituminous coal, which is softer than anthracite. Further, as will be described, the present invention has a much more restricted particle size range as well as concentration range.
Notwithstanding the foregoing, there remains a need to provide an additive for drilling fluids which will more effectively operate both as a shale stabilizing agent and a seepage loss agent in subterranean wellbores.
Accordingly, it would be desirable to provide an additive for drilling fluids which would both prevent seepage loss and act as a shale stabilizing agent in subterranean wellbores.